E STIMATION OF INPUT PARAMETERS

To be able to use the framework presented in the previous section to value DETNOR, some input parameters must be determined. This includes the different costs, probabilities, taxes and the reserve size. The inputs in relation to oil price forecasting were presented in section 8.3. Most of this information is impossible for an outside analysis to get a hold of, and as a result some of the inputs are educated guesses based on historical data. Consequently, a thorough sensitivity analysis will be presented in the last part of the real option valuation to get an overview over how sensitive the share price is to the most important input parameters.

11.2.2 Production and petroleum reserve size

The production phase of a petroleum license is the only period when the company get cash inflows. To successfully find the value of a production license, the parameters related to the production phase are imperative to estimate accurately. There are two main variables that are

used to predict production: the reserve size and the production profile. The next sections will be an explanation of the estimation of these variables.

11.2.2.1 The reserve size

The reserve size is the size of the available petroleum below the seabed in an area. Before there has been invested in exploration there is no information to indicate how large the possible reserve may be. In the case of DETNOR´s exploration and production licenses where no such investment has been made, the reserve size must be estimated. The difficulty is that by looking at the average reserve size historically on the NCS, the estimated size will likely be largely overvalued. This is due to the fact most large fields, have most likely already been discovered. This is not always the case, such as with Johan Sverdrup, which is one of the largest fields on the NCS and discovered fairly recently. However, most experts do not believe this will happened again, especially not in the mature areas of the North Sea and Norwegian Sea (Norwegian Petroleum Directorate, 2014).

As DETNOR is a fairly young company, most of their petroleum resources have been discovered in recent years. To find an approximation of the reserve size for a mature production license, the average of the company´s exciting field has been calculated. The Johan Sverdrup field has been excluded, as a discovery of that size is unlikely to reoccur. This gives an average size of 50,000,000 boe per production license in mature areas.

To estimate the expected reserve size in immature areas other methods have had to been used as the company has only one field with established resources. There is only one immature field currently in production on the NCS, Snøhvit. Both of these have a size around 200,000,000 boe and this has thus been used as a proxy for size of an immature petroleum license. The estimation of four times as big field with immature field is in line with the Norwegian Petroleum Directorate´s (2014) predictions that it is only in these area where there can be expect to locate large petroleum resources.

11.2.2.2 The production profile

Figure 11.2.1: A typical production profile for a petroleum field.

Source: Höök et al., 2009

A production profile for a field is an overview of how the recovery of resources is spread throughout the estimated production period. Every field will have a different production profile, and this will again develop over time as the technology improves. There are a few trends that are visible on all fields. The first years after initiation, the volume is relative low with an upward sloping trend. This is as a result of that it takes some time from the production starts until the facilities are fully up and running. Many companies start to produce even though the entire production facilities are not completely in place. The production soon reaches a top level, and stays there for a period. The pressure in the reservoir is the highest while it is relatively full, and falls as the amount of recoverable reserves diminishes. The production will peak fairly early and have a downward sloping trend until the field is abandoned (Höök et al., 2009). Figure 11.2.1 illustrates a typical oil field production profile.

Figure 11.2.1 has also been the model for the production profile for DETNOR´s licenses. To make the computations as simple as possible, the production after the peak is straight and not downward sloping. This may make the cash flows somewhat downward biased, but it the complexity of the model will be greatly reduced. The complexity occurs as a result of that all of the developing or producing fields have different time frames, and needs to be modelled independently. The production profile for a 15-year field is as showed in figure 11.2.2. Two exciting closed-down fields have been used to compare the estimated production profile to actual production profiles.

Figure 11.2.2: The estimated production profile for a producing field compared to two real closed-down fields.

Source: Own contribution

11.2.3 Probabilities

A firm in the upstream petroleum sector will experience some reserve uncertainty in the earliest stages of development. This includes uncertainties regarding where in the oil field there may be petroleum, if there is petroleum present and if the petroleum found is viable for production. The

0,0%!

5,0%!

10,0%!

15,0%!

20,0%!

25,0%!

1! 2! 3! 4! 5! 6! 7! 8! 9! 10! 11! 12! 13! 14! 15!

Production profile! Glitne! Huldra!

probability of finding petroleum will differ if the license is mature or immature. There is no available external data on these probabilities and they are based on predicted values. Historical data could have been used, but there is neither complete data available nor does it capture the entire uncertainty a firm will experience at time zero. It is also likely that it will be a lower probability moving forward of finding commercial petroleum than it was in the past. Table (11.2.3) describes the probabilities used in the model.

Table 11.2.3: An explanation of the observed probabilities.

Source: Own contribution

The probabilities have been predicted based on the available information about the remaining resources on the NCS, mostly from the Norwegian petroleum directorate (2014). These are not exact estimations, and they will thus be sustainable to approximation errors. As a consequence, the sensitivity of the firm-value to these probabilities will be carefully reviewed in the sensitivity analysis.

11.2.4 Costs

Companies operating in the petroleum industry face large fixed cost. These represent large risks for the company because as much as 70 percent of total costs are incurred before production has started. Determining the different costs at the different stages is thus an important part of the analysis. The estimated inputs will be split into three different categories: investment costs, operating costs, and abandonment costs.

11.2.4.1 Investment costs

Investment costs are the costs that are related to locating petroleum and building production facilities. From part 4.4 and 11.1 it is evident that each phase before production in the value chain of an exploration and production license is represented by a different investment cost. The simplest costs to identify are the development costs found in stage four “building production facilities”. For licenses where the PDO have been delivered is the costs pubic information. For licenses in earlier stages of the development, where the company have not applied for PDO, this number is not public and maybe not even estimated by the firms. For these the expected development cost is the

average development cost per boe multiplied by expected production. The expected development cost per boe is calculated by looking at DETNOR´s exciting portfolio of projects where this this cost is known and divide by the projects projected boe.

The development cost per boe will differ if the license in question is in a mature or immature area of the NCS. As immature field does not have any existing infrastructure in place, the costs of building production facilities will be much higher. Currently, there are not delivered many PDOs for licenses in immature areas, but there is one field in the Barents Sea, Snøhvit, where production has started. The development cost per boe for this field was $30. This is more than three times of the estimated development cost for fields in mature areas, which was $9. The cost per boe from Snøhvit is consequently used as a proxy for development costs for projects in immature areas.

The investment costs in the first two phases are more challenging to estimate. The first phase is the exploration phase. The costs included here are investments in seismic tests and trial drilling, also known as wild-cat drilling. The costs related to this stage of the development of license are hard to estimate, as they are not explicitly separated by project in the firm’s annual reports. The second stage is the appraisal drilling, which ensures if the discovery in stage one is commercial.

This is done by drilling more wells, which determines the size and type of petroleum available. The appraisal drilling costs are not either presented separately by the company.

According to the Norwegian Petroleum Directorate (1997), 12% of total costs for an upstream petroleum company will be related to the exploration and planning phase. This is interpreted to include the first two stages of the production chain. The development costs are on average 58% of total costs (Norwegian petroleum directorate, 1997). Total costs are calculated by looking at developing costs, and dividing these costs by 58%. Total costs are calculated in this manner to decrease complexity, as operating costs will vary with production. The exploration and planning costs are hence calculated as 12% of total costs. Based on the investments required in the different stages it is estimated that 2/3 of the costs will be in the exploration phase and 1/3 of the cost in the appraisal drilling phase. The reason for this distribution is that there is usually drilled more wild-cat wells than appraisal wells, and that the acquisition of seismic data is very costly (Norwegian petroleum directorate, 2014). An overview of all investment costs can be found in appendix 31.

11.2.4.2 Operating costs

The operating costs are the expenses associated with DETNOR´s production. These include costs linked to leasing, operating and maintenance of subsea installations, modifications, and production ships/platforms. Environmental tax is also included in the operating costs. It also includes the

share of payroll and administration expenses that can be attributed to operations (DETNOR, 2014n). The operating costs for the entire company can be found in DETNOR´s annual reports. It has been assumed that these costs vary with the production level i.e. number of boe. Operating costs per boe is calculated by dividing “Total production costs” by “Total production (boe)”.

Operating costs are considered variable costs and are deducted from the expected oil price to find operating income. Total operating costs will therefore vary with the expected production.

11.2.4.3 Overhead costs

Overhead costs are on-going expenses that are not directly related to a firm´s operation and thus cannot be traced to a specific field or license. In the case of DETNOR, the overhead costs are the cost found in the “Other operating costs” their annual report. These include office costs, IT-costs, advertising, travel expenses, underwriting and consultant fees, area fees, preparations of development licenses and other expenses. It can be argued that some of these costs will vary with production and should therefore be added to the variable operating costs. However, as most of the fees are decidedly fixed, all overheads will be incorporated into the valuation model as a fixed cost.

The costs will be directly deducted from the estimated company value using the following perpetuity formula:

(11.9) !"!!"#$ℎ!"#!!"#$#=!!"#$!!"#!!"#$#!∗!(!!!"#)

!

11.2.4.4 Abandonment costs

When companies in the petroleum industry in Norway build production facilities at sea, companies are not allowed to forsake these when there is no more petroleum left. To preserve the environment, there are rigid requirement for the shutting down procedure for such facilities. The facilities must be removed and the area cleared. Each licensee must present a “plan of cessation”

to the Norwegian Ministry of Petroleum between two and five years before the production ends (Norwegian Petroleum Directorate, 2014).

The cost of this is quite large and it is important to estimate this when valuing DETNOR. The basic assumption is that the abandonment costs are based on reserve size. It is therefore assumed that the large the reservoir, the larger the costs. This may not be the case in the real world, as it will depend on the types of production facility used and the number of other producing fields in the area. However, looking at these factors for all of DETNOR´s licenses will be a very comprehensive task and outside the scope of this thesis. The abandonment cost for each license can be view in appendix 34.

11.2.5 Taxes

The taxes are an important element to incorporate in any model of petroleum projects, as the marginal tax rate on the NCS is as high as 78%. The tax regulations regarding petroleum activities are very comprehensive and complex, and including all elements of these is outside the scope of this thesis. However, the most important aspects must be included to get a realistic value of a license. This includes the special rules regarding exploration costs, depreciation on production facilities, uplifting, and petroleum income.

In the model, the petroleum income has been taxed with 78%, which is consistent with the PTA.

The presented project value is an after-tax figure. The present value of the abandonment costs that have been deducted the expected value, is the after-tax value. This is consistent with current regulations, which states that abandonment costs can be expensed when incurred. The regulations of expensed as incurred are also true for exploration costs (Deloitte, 2014). These are also presented in the model on an after-tax basis.

The challenge in terms of modelling the after-tax value of a petroleum project is in terms of the production facilities. Production facilities are depreciated in a straight-line over six years. The total investment costs can use an uplift of 22% (5,5% annually over four years), to reduce the amount taxed at the offshore tax of 51% percent (Harboe, 2014). The following example illustrates how the uplift is used. To start, a normal corporate tax at 27% is calculated on EBT. The uplift is then deducted from the profit margin before tax, and a special tax of 51% is added on the remaining amount. The two amounts of tax are then added together and total company tax is established (Harboe, 2014). As this is too complicated to incorporate in the value of all the 79 licenses that the company possesses, simplifications has been made. A tax percentage has been calculated that represent the same after-tax amount as calculating the full depreciation and uplift cycle. This percentage represent the effective tax rate the company would have if written the asset off immediately. This percentage is used to calculate the after-tax cost of investments in production facilities and is lower than the general tax of 78%. The method can be view in appendix 33.